Analysis and Future Prospects for Cross-border Congestion Management Methods for the European...

Electr Eng (2007) 89: 509–517DOI 10.1007/s00202-006-0031-5

ORIGINAL PAPER

Nikolaos Athanasiadis · George E. ChatzarakisEfstathios Athanasiadis · Dimitrios Fourlaris

Analysis and future prospects for cross-border congestionmanagement methods for the European electricity market

Received: 8 April 2006 / Accepted: 12 May 2006 / Published online: 20 June 2006© Springer-Verlag 2006

Abstract This paper presents an analysis of current and po-tential cross-border congestion management methods for theEU electricity market. Many currently used techniques are re-ported and the main aspects of possible future are presented.The main steps of the newly established coordinated auc-tion technique will be reported and an example of a real casefor the South European Region will be implemented. More-over, in order to eliminate loop flows, avoid congestions atthe day ahead stage and increase the total transfer capacityof the south UCTE region (countries Greece, Albania andFYROM), it will be shown that Flexible Ac TransmissionSystems technology can help market players to get access tomore transfer capacity for their transactions, while securitymargins are being maintained.

Keywords Congestion management · Auctions · FACTS ·Coordinated auction

N. Athanasiadis (B)Hellenic Transmission System Operator (HTSO),Operational Planning Department,Asklipiou Street 22, 145 68,Krioneri, Athens, GreeceE-mail: [email protected].: +30-694-2059010

G.E. ChatzarakisElectrical Engineering Department,School of Pedagogical and Technological Education (ASPETE),N. Heraklion, 14121 Athens, GreeceE-mail: [email protected].: +30-210-2896774

E. AthanasiadisLeonidou 23, Xarilaou,54250 Thessaloniki, GreeceE-mail: [email protected].: +30-231-0305953

D. FourlarisSystem Security Department,HTSO, Asklipiou Street 22,145 68, Krioneri, Athens, GreeceE-mail: [email protected].: +30-210-6294232

1 Introduction

The ongoing liberalisation of electricity markets that requiresthe unbundling of production, transportation, trading and dis-tribution results in a continuous increase of power flows inthe grid that become difficult to predict.

In a liberalised electricity market, the transmission capa-bility of a transmission system is of an economical valueto a network company. Network companies have a naturalmonopoly combined with the commission to maximise thebenefit for their customers while giving a reasonable profit totheir owners. Due to physical constraints at the surroundingnetwork, the lines are often only utilised at a fraction of theirindividual limits. To improve customer benefit one possibil-ity would be to add to the value of the transmission lines byincreasing the amount of transported energy over these lines.Additionally, there will be a gain in overall market efficiencysince more energy trading can take place between competingregions with different price structures.

In this paper, preventive congestion management tech-niques that are currently used and the ones that will be usedin the future will be reported, followed by correcting manage-ment innovative solutions that can be used at the day aheadstage, such as implementation of FACTS controllers. FlexibleAC Transmission Systems (FACTS) devices is a new tech-nology which allows the increase of the overall utilisationof electrical power network by controlling the power flow.It will be shown that power flow controllers can be used inorder to avoid congestion and so to increase the total transfercapacity (TTC).

There are several publications in the literature relevantto cross-border congestion management with specific objec-tives:

In [1] and [2], different power flow controllers are beingapplied to power systems to face congestion managementproblems. In [3], various cases with traditional auctions tech-niques are being analysed while in [4] and [5] similar studiesshowing the advantages and disadvantages of explicit andimplicit auctions are being implemented. In [6], the use ofthe promising decentralised market coupling is mentioned.

510 N. Athanasiadis et al.

Fig. 1 Congestion management timescale

These examples clearly show that there are not many con-tributions in the literature to discuss the whole procedureof the congestion management procedure which includesthree different time-dependent stages. Moreover, there areno examples with the use of FACTS controllers using realexamples taken from the TSOs.

In this paper, the newly established co-ordinated explicitauction technique is presented and implemented in the SouthEast European region and innovative FACTS controllers areused for congestion elimination.

2 Congestion management systems

Congestion management systems(CMS) can be classified inthree different time ranges [1] as seen in Fig. 1 and describedin the following sections.

2.1 Preventive congestion management systems

The preventive CMS may be subdivided into long and short-term CMS. Both kinds of preventive CMS aim at avoidingthe development of generation schedules which could lead tocongestion situations.

Long-term preventive CMS refers mainly to power sys-tem planning. Short-term preventive CMS are measures whichare usually taken on a day ahead basis, e.g. market splitting orauction market. With an increasing deregulation of electricitymarkets, fixed structures with long-term contracts, etc. dis-appear and the markets become more flexible. Sometimes,it becomes increasingly uncertain and difficult to performsome of the preventive CMS measures. Therefore, it will be

important in the “completely-deregulated” future to correctthe generation schedules by means of correcting CMS.

2.2 Correcting congestion management systems

In liberalised electricity markets it seems that on the dayahead of the actual power flow, the pattern of the genera-tor power feeding and the predicted load are known to thenetwork operator. After this point of time up to the actualpower flow, it is possible for the network operator to performsecurity calculations and if necessary to avoid congestions.In this case, congestion means the violation of thermal andvoltage limits under consideration of (n−1)-contingencies inthe system.

The cost free actions (operating costs are not taken intoaccount), which can be taken by the network operators tosolve the congestion problems, are as follows:

• Topology change• Changing of transformer tap position• Operation of conventional compensation devices• Set-point variations for FACTS

If these actions are not sufficient to solve the congestion prob-lem, it is necessary that the network operator spends moneyfor advanced measures.

The network operator may allocate these costs to the net-work users (e.g. by means of an additional component withinthe network charge). The structure of the electricity marketdetermines the way this cost allocation is done.

The network operator has to pay the power plants for theenergy delivery. And normally the power plants have to paythe network operator to reduce their energy delivery. It is

Analysis and future prospects for cross-border congestion management methods for the European electricity market 511

quite obvious, that the power plant is just willing to pay aslong as the price has not reached its generation costs, whereit starts to realise profits. It is the task of the network operatorto guarantee the power supply of the customers of the powerplant which has reduced its energy delivery.

The reactive power of the power stations must also bepurchased by the network operator as a system service.

2.3 Reacting congestion management systems

Reacting CMS are those measures which are taken on theday of service immediately after a congestion has occurreddue to, e.g. network faults, disturbances and major schedulevariations. In order to avoid a critical situation for the entirenetwork, it is necessary that the network operator has theright to use all technical possibilities to solve the problem[2]. This includes those measures which have been availablebefore the deregulation (e.g primary and secondary reserve,re-dispatch, etc.) The main thing which has changed is thefinancial side of the transactions.

After a stable operating point has been reached again, itis possible to start the same measures as for the correctingCMS, if there is a danger of a permanent congestion situation.

3 Preventive congestion management methods

3.1 Curtailment based on published Net transfer Capacities

The operation of the European power system requires asufficient knowledge about generation and load programs(day-ahead and real-time) within each control area, as wellas between them. Without this information, TSOs are notable to inform market participants of the precise probabil-ity of constraints, to prevent constraints or to apply curativeactions.

Several levels of data exchange are possible and recom-mended between partners. The publication of net transfercapacities (NTCs) which relate to the capacity of exchangesbetween two areas is the minimum information which is re-quired to be used as an indicator to allow market actors toevaluate the risks of seeing their transaction curtailed [3].

Formally, the NTC represents the best estimate limit forphysical electricity transfer between two control areas. NTCis defined by the TTC of an interconnector or more often byseveral interconnectors that link two control areas, reducedby a transmission security margin (TRM).

When NTCs are used as an upper limit for the availabletransmission capacity, no further capacity can be allocatedby TSOs once the limit is reached. Then the method requiresthat a mechanism to define the priority for using NTCs beimplemented.

Values for NTCs are published, transmission service cus-tomers give their demands to the TSOs, and transactions thatwould cause overloads are rejected according to a predefinedpriority rule.

3.1.1 First come, first served method

The first reservation made for a given period of time has prior-ity over the following reservations. Once the interconnectioncapacity is reached, the transactions are not accepted by theTSO anymore.

Each reservation has to be confirmed at least on day D-1.The method encourages participants to make longer fore-

casts. Thus, it allows better and sooner security assessmentfor TSOs who know accurately the volume of exchanges inadvance.

One drawback is that in some cases, the method may notleave enough room for short-term trading, which is a require-ment to ensure the success of a market dynamics.

3.1.2 Pro rata rationing

In this case no real “priority” is defined. All transactions arecarried out but the TSO curtails them in case of congestionaccording to the ratio: existing capacity/requested capacity.

The method is transparent to the users, but brings eco-nomically inefficient use of the system: everyone being cur-tailed relatively to the amount submitted to the TSOs, noincentive is given to reduce congestion either to the partici-pants, or to the TSOs. In the absence of regulatory mecha-nism, it may also lead to artificially over-evaluated amountsof transactions (leading to gaming by offering inconsistentvolume of transaction).

The main drawback of the methods that are based on cur-tailment of transactions based on NTCs publication is thatthey do not convey any economic incentive. No incentives aregiven to TSOs, generators, distributors, traders and thereforedo not promote efficient trade.

3.2 Redispatching and counter trading

When transactions exceed NTC, transaction-based methodsrequire the curtailment of transactions, and physical bound-aries then become a limit to trade. In this situation, the redis-patching of generation in the constrained TSO’s own controlarea may help to relieve part of the congestion. To redis-patch, the TSO requires information on prices to modulategenerators up and down. Redispatching, in general, createsadditional costs for the TSO, which could be allocated tothe responsible parties (i.e. market players involved in ex-tra cross-border transactions), for the sake of economic effi-ciency.

The additional costs may also be shared equally amongall traders. However, this may increase congestion problemsdue to the lack of price signal.

Under counter trading the TSO first undertakes a leastcost unconstrained dispatch [4].

Counter trading and redispatching are characterised bythe following:

1. Under counter trading all economic rents are passed tocustomers in the high cost country. Instead of collecting


rents, the TSO suffers costs as a result of the constraint.This gives a clear economic signal to the TSO about theseriousness of the constraint. High constraint costs are asignal to upgrade the network.

2. Counter trading requires a common balancing mechanismin both countries,where, in theory redispatching merely requires knowledgeof generator’s costs. However, in practice there is littledifference between counter trading and re-dispatching onthe basis of economic precedence.

3. Both redispatching and counter trading provide no fundsto the TSO to upgrade the network.

3.3 Explicit auctions

Explicit auctions are market-based methods for transfercapacity allocation, where capacity is traded among the mar-ket participants separately from the electricity [3]. Classic ex-plicit auctions are related to the allocation of the NTC valueon the border between two neighbouring TSOs. NTC is as-sessed and published by the neighbouring TSOs and it is themeasure of the transfer capacity which is to be allocated inauctioning process. The NTC can be divided between neigh-bours (most common is 50:50) and then each TSO allocateits part, or can be jointly auctioned by the TSOs. The marketparticipants give the bids for the transfer capacity. All bidsare collected at the auction office and ranged from the highestto the lowest. The bids with the higher offered price for theuse of the capacity are accepted until the NTC is completelyfilled. The last accepted bid can be partly accepted. If thecapacity is not totally accepted, i.e if the NTC is sufficient,the market participants are not charged for the transmissionfee (no congestion–no payment). On the other hand, if onlysome of the transactions “pass” the auction, they are chargedfor the transmission fee. The usual case is that the last ac-cepted bid gives the marginal price and all the accepted bidsare charged with it.

Explicit auctions are characterised by the following:

1. Auctions can be prone to gaming. Some generators maynot require interconnector capacity at all but still try tobid up the price to damage their competitors.

2. Depending on the design of the auction, the economicrents available will tend to be collected by TSOs as aresult of the auction. If these are split evenly between thetwo connected countries to reduce network charges, thenthe difference in final electricity prices will probably notbe significantly eroded.

3. Auctions do not require a common balancing mechanismin the two countries, whereas alternatives do require sig-nificant harmonisation of balancing rules.

4. TSO rents can be used for expansion of the systems.

3.4 Market splitting/implicit auctions

This method consists of splitting a power exchange (PEX)into geographical bid areas with limited capacities of

exchange; a power pool price is set according to amountsof demand and generation offered in the whole market area.Then the TSO computes a load flow and identifies constrainedlines [5].

Geographical areas, composed of one or more bid ar-eas, are defined on either side of the bottlenecks. In eachgeographical area, a new pool price is defined, flows acrossareas being limited to the capacity of the interconnectionlines. Then each area has its own pool price: areas down-stream of a congestion will have a higher pool price, areasupstream of a congestion will have a lower pool price. Whenthe price–demand effect is observed (demand decreases asprice increases), the congestion is relieved through the mar-ket mechanism: demand decreases in high-priced areas, andincreases in low-priced areas. Obviously, the opposite effectis seen at the generation side.

Consumers downstream of a congestion will pay the high-est prices, and generators upstream of a congestion will bepaid the lowest prices. The congestion charge is the differ-ence between the price in downstream area and the price inupstream price area; it is collected by the system operatorand is used to lower the tariff for generation and load withineach system.

In this method, congestion relief relies partly on the mar-ket forces, being based on the sale-price and purchase-pricecurves. Trade will be maintained if the price in the corre-sponding price area ensures profitability for the market ac-tors. The market-splitting concept thus encourages tradingas far as market actors receive ex-ante information about theprobability of congestion between some areas.

The model should also be beneficial with regard to a betterlong run use of the network.

An advantage about the market splitting method is thaton a long-term basis, customers may react to high pricesin congested areas by substituting other forms of energy toelectricity. New generators may also decide to connect tothese zones of shortage, attracted by high sale prices, andthus introduce more competition and cause overall prices todecrease.

Another advantage of market splitting is that a price signalis available to all market participants, particularly for gener-ators who can base their production on this price signal: thenall generation with a marginal cost lower than the marketprice will run, while all others will stop.

The main problem with market splitting is its feasibilityon a large scale. The system will work best if there is a com-mon market structure and organisation (an electricity powerexchange) on both sides of a constrained border.

With implicit auction, markets are split in the same wayas with market splitting; however, the successful exporter isthe lowest cost company rather than the marginal producerof the exporting country in market splitting.

Market splitting and implicit auctions characteristics:

1. Market splitting and implicit auctions are much less proneto gaming than the explicit auction since the generatorsare not bidding for economic rents but sell at a commonsystem price.


2. The economic rents will be shared between customers inthe high cost country and TSOs under market splitting.No economic rents are available to generators.

3. These mechanisms require a common balancing mecha-nism in both countries.

3.5 Coordinated auction

The coordinated auctioning(CA) method is the extension ofthe bilateral explicit auction mechanism, enhanced with themore accurate presentation of the physical behaviour of theinterconnected system.

Its main idea is the simple presentation of the meshednetwork effects through the load flow factors (power flowdistribution factors,PFDF), where each exchange scenario iscoupled with the set of PFDFs that show the distribution ofthe physical active flows in the interconnected network. Thenetwork is divided into zones separated by borders or inter-connections. These zones could be the TSOs.

The following steps are applied:

• The TSOs compute the PFDF matrix which shows thecontribution of the transactions among the zones as thephysical flows at the borders between the zones.

• For each border between the neighbouring zones, linkedby existing physical tie-lines (electrical border), the neigh-bouring TSOs compute together the technical constraintsthat limit the physical flow at the respective border. Thislimit is called border capacity (BC) and it should be de-fined for both directions.

• The PFDF matrix and the set of BCs should be publishedand offered to the market participants. The set of infor-mation requested by the TSO includes the PFDF matrixand BCs.

• TSOs organise the simultaneous (coordinated) auctions,where, market participants send their bids consisting ofa quantity and price for the transmission right they wantto buy.

The set of information requested by the market participantsincludes the:

Quantity [MW], destination (source and sink area), bidfor the transmission right.

In the clearing process, the selected bids are the onesthat combine the best overall economic value for the marketunder the physical and security constraints. In other words,if there is a congestion of some border (=influence of all bidsat that particular border exceeds the offered BC), some of thetransactions should be rationed. The main idea is to curtailthe transaction with the highest influence at the congestedborder/the lowest offered price, the highest ratio PFDF (atcongested border)/bid.

If there is no congestion, nobody will be charged (no con-gestion, no payment). If there are some congestions, some ofthe transactions will be curtailed as described above, and allthe transactions that passed, will be charged according to theirPFDF. The last accepted bid gives us the marginal price andit will be charged with it. Other accepted transactions will

be charged on the basis of that marginal price, but multipliedwith the ratio of their PFDF at congested border/PFDF of lastaccepted transaction at that border.

The transactions that relieve the congestion (=their PFDFis negative) will be rewarded according to their PFDF at thecorresponding border.

So the clearing process is the following:With no congestion, no paymentIf there is a congestion on border i:Transaction x with highest PFDFx (i)/Bidx will be cur-

tailed. The above

bidx = marginal price(MP) (1)

All transactions j that have PFDF j (i) > 0 will be chargedproportionally to their PFDF:

MP ∗ (PFDF j/PFDFx ) (2)

The transactions k with PFDFK (i) < 0 will be rewardedproportionally to their PFDF

MP ∗ (PFDFk/PFDFx ) (3)

The method has a few variants (zone to zone, zone to hubcalculation) and shares of congestion charges. Moreover, aPFDF-based model allows for a comprehensive considerationof “netting”, i.e. the physical compensation of power flowsin opposite directions.

If capacity is allocated using a PFDF-based model, socialwelfare increases by almost 25% compared to the referencecase. This result underpins the conclusion that the inherentadaptation to the market price volatility is a significant advan-tage of PFDF-based allocation and that this effect is relevantunder realistic market conditions. At the same time, both thevolume of cross-border power exchange and the aggregatedphysical flows on the flow gates increase by the same order ofmagnitude. PFDF as a consequence of reduced uncertaintiesallows for a more even utilisation of the different tie lines.

3.6 Implicit coordinated auction and decentralised marketcoupling

The implicit CA method has many similarities with the sim-ple implicit auction method, however, it is based on flows(use of PFDF factors) instead of NTCs. A common powerexchange is required for the total number of TSOs. The cal-culation of the PFDF matrix follows the same procedure asin the CA case. This method coordinates the energy and thetransmission allocation without disadvantaging the ones withrespect to the others.

The decentralised market coupling method is similar tothe implicit CA method, but is applied in a larger scale andincludes many power exchanges [6].

There may be some advantages with implicit auctionmechanisms; however, the realisation of a pure implicit auc-tion for the European electricity market would ideally requirethat a joint coordination of energy markets and transmissionallocation through the EU be implemented. Power exchangeswould require regulation. However, this is very difficult for


Fig. 2 Functional model of UPFC

the moment. Legislation, would probably be needed to re-quire that all cross-border trade go through those markets.Therefore, it is unlikely that a pure version of an implicitauction variant would be applied in a pan-European level inthe next few years.

4 Innovative solutions for correcting congestionmanagement

As mentioned above, correcting CMS takes place the D-1 day,after generator feeding and predicted load are known to thesystem operator. FACTS technology can be used as an inno-vative effective solution to solve congestion managementproblems at this stage [7]. The UPFC, as the most advancedof FACTS controllers, is analysed and tested in real-case sce-narios in the paragraphs that follow.

4.1 Unified power flow controller principles and operation

This paragraph is concerned with the unifird power flowcontroller(UPFC) controller where two synchronous voltagesource converters (VSCs) employed in combination are usedfor real-time control of power flow in transmission systems.

DC terminals of both converters are connected to a com-mon dc capacitor. The basic three-phase UPFC scheme isshown in Fig. 2. Figure 2 shows that if the series branch isdisconnected, the parallel branch comprised of a dc capac-itor, VSC-1 and a shunt connected transformer correspondsto a static compensator (STATCOM). Since the STATCOMcan generate or absorb only reactive power, the STATCOMoutput current is in quadrature with the terminal voltage.

If the parallel branch is disconnected, the series branchcomprised of a dc capacitor, VSC-2 and a series injectedtransformer corresponds to a solid state series compensator(sssc). The SSSC acts as a voltage source injected in seriesto the transmission line through the series transformer; thecurrent flowing through the VSC is the transmission line cur-rent, and it is a function of the transmitted electric powerand the impedance of the line. The injected voltage Vsr isin quadrature with the transmission line current line with themagnitude being controlled independently of the line current.Hence, the two branches of the UPFC can generate or absorbthe reactive power independent of each other.

If the two VSCs are operating at the same time, the shuntand series branches of the UPFC can basically function as anideal ac to ac converter in which the real power can flow ineither direction through the dc link and between the ac termi-nals of the two converters. The real power can be transferredfrom VSC-1 to VSC-2 and vice versa, and hence it is pos-sible to introduce positive or negative phase shifts betweenvoltages Vs and Vr. The series injected voltage Vsr can haveany phase shift with respect to the terminal voltage Vs.

The VSC-2 is used to generate the voltage Vsr at funda-mental frequency, variable magnitude and phase shift. Theharmonic content in the voltage Vsr depends on the designand control of the VSC-2. This voltage is added in series tothe transmission line and directly to the terminal voltage Vsby the series connected coupling transformer. The transmis-sion line current passes through the series transformer, andin the process exchanges real and reactive power with theVSC-2. This implies that the VSC-2 has to be able to deliverand absorb both real and reactive power.

The shunt-connected branch associated with VSC-1 isused primarily to provide the real power demanded by VSC-2 through the common dc link terminal. Also, since VSC-1


can generate or absorb reactive power independently of thereal power, it can be used to regulate the terminal voltage Vs;thus, VSC-1 regulates the voltage at the input terminals ofthe UPFC.

Another important role of the shunt UPFC branch is a di-rect regulation of the dc capacitor voltage, and consequentlyan indirect regulation of the real power required by the se-ries UPFC branch. The amount of real power required by theseries converter plus the circuit losses have to be suppliedby the shunt converter. Real power flow from the series con-verter to the shunt converter is possible and in some casesdesired; in this case, the series converter would supply therequired real power plus the losses to the shunt converter.

The power rating of a converter is derived from theproduct of the maximum continuous operating voltage andmaximum continuous operating current. The series convertermaximum voltage is determined based on the function thatthe UPFC is designed to perform. The shunt converter has twofunctions: one is to supply real power to the series converterand the other one is bus voltage control. The maximum con-tinuous rating should take into account the amount of reactivepower needed for voltage control at the point of connectionwith the ac system.

5 Test results

5.1 Preventive congestion management: coordinatedauction in the South East Europe

In order to calculate the PFDF factors between two coun-tries, the production in the exporting country is increased by+100 MW, while the production in the importing country isdecreased by the same amount. The change in power flowson borders gives the PFDF factors. TSOs jointly calculatethe PFDF matrix. In order to establish the BC values, the BClimit can be taken as the 90% of the total transfer capacity(TTF) in the tie-lines.

TSOs bilateraly calculate and harmonise BCs on theirborders.

PFDF matrix and set of BCs for the respective time frameis offered to the auction.

The participants send the bids for specific transmissionrights.

Auctioning Office administrates the clearing accordingto the received data from TSOs (PFDF, BC) and market par-ticipants (bids).

The calculation procedure includes the following steps:1. Turning all the bids with PFDFs in border flows:[Bids] x [PFDF matrix] = [Power flows on borders]2. Clearing criteria: [Power flows on borders] < [BCs]If all calculated flows < BCs: No congestion, no paymentIf some calculated flows > BCs: e.g. Congestion on bor-

der i: Bid with smallest ratio: Bid[EUR]/ PFDF(i) will bedecreased

For example for the 3rd week of November 2004 the TTFBlagoevgrad–Thessaloniki was calculated as 580 MW, lead-ing to a BC value of 522 MW (with the 0.9 factor).

So BC (BG–GR)=522 MWBid 1: RO–GR, 292 MW, 2 EUR/MW, at BG–GR border:

PFDF=62%Bid 2: BG–GR, 300 MW, 3 EUR/MW, PFDF=65%Bid 3: RO–FYROM 350 MW, 2 EUR/MW, PFDF=45%� (flows 1,2,3) on BG–GR border: (292*0.62+300*

0.65+350*0.45)=533 MW11 MW of congestion!Bid RO–GR_1: p/PFDF=2/0.62=3.22, smallest offered

price per 1 MW on congested border due to the fact that theBG–GR 2: 3/0.65=4.6 and RO–FYROM 3: 2/0.45=4.44

Last (partially accepted) bid RO-GR sets up the marginalprice: MP =2 EUR/MW

Other bids that influence the congestion (BG–GR andRO–FYROM) pay according to their PFDF at congested bor-der:

Payment BG–GR: 2×65/62 =2.1 /MWPayment RO–FYROM: 2 EUR×45/62 =1.45 EUR/MWTotal income: 2×274+2.1*300+1.45*350=1668 EUR to

be shared among TSOs BG and GR.

5.2 Correcting congestion management

One aspect of how FACTS devices can be used for correctingCMS in order to improve inter-regional transmission capac-ity and increase the TTC will be illustrated by an exam-ple based on a real-case scenario for the South East Euro-pean region. This base case model was taken on the 1st ofMarch 2005, 10.30 CET (Central European Time). A graphi-cal representation of this network configuration is illustratedin Fig. 3.

In region B (Bulgaria) there is a large amount of nuclearpower generation installed, leading to low electricity prices.Region C (Greece) has high prices due to a deficit in genera-tion. Starting condition is the base case, without any FACTScontrollers installed, and the ratings for the interconnectedlines are from Blagoevgrad–Thess 830 MVA, from Dubrovo–Thessaloniki 820 MVA and for Meliti–Bitola 100 MVA.

We will show how the installation of controllable de-vices make possible to increase the power flows (the TTC)in the importing countries (GR,FYROM,ALBANIA) with-out decreasing security limits. This will increase the overallmarket efficiency since trading will be less constrained byunavailable transfer capacity.

In Fig. 3 the arrows of the vectors show the directionof the power flow. Region C is connected through a 400-kV line with region B (the line Blagoevgrad-Thessalonikior BC), with a 400-kV line (Dubrovo–Thessaloniki or AC2)and a 150-kV line (Bitola–Meliti or AC1) with region A (FY-ROM) and exports to D (Albania) though a 400 kV line CD,while the DC connection to E (Italy) is open. Overall, sumsof 500 MW are imported into region C, area D has a zerototal exchange and area A (FYROM) has a total import of150 MW.

The PSS/E power systems analysis software is used forthe load flow studies with and without the UPFC controller.


Fig. 3 Base case system under consideration

Table 1 Results with and without the UPFC with programs GR: −500 MW, FYROM: −150 MW and ALBANIA: 0 MW

Cases LinesAC-1 AC-2 BC CD TTC (GR+AL+FYR)

Case 1, GR: −500, AL: 0, FYR: −150 MWLoading of the line (in % in MVA) 36.0% 8.0% 70% 31% 670Trans (MW) 35 −3 632 164

Case 2 with a 100 MVA UPFC in GR–AL tie lineLoading of the line (in % in MVA) 3% 12 % 62% 7% 790Trans (MW) −1 −60 561 0

In Table 1, we can see the results of the analysis where a100 MVA UPFC was added to the Kardia–Zemlak (line CD)tie-line. In case 1, there is no FACTS element where in case2, a 100 MVA UPFC is applied.

The outcome of the above analysis is that with programsof GR: −500 MW, AL: 0 MW and FYROM:−150 MW theTTC for the total region (AL+FYR+GR) was increased by120 MW (from 670 to 790). The TTC limit in both cases canbe found when an outage of the Kosovo–Skopia tie line (be-tween Serbia and FYROM) leads to 100% loadingof the Blagoevgrad–Thessaloniki (Bulgaria–Greece) tie line.

With programs of GR: −500 MW, AL: −200 MW andFYROM:−200 MW the TTC for the total region (AL+FYR+GR) was increased by 170 MW (again with a trip in Kosovo–Skopia that leads to 100% loading of the Blagoevgrad–Thes-saloniki, line BC, limit).

In Table 2, again in case 1 there is no FACTS elementwhere in case 2 a 100 MVA UPFC is applied.

The UPFC in the previous case has its series connectedtransformer injecting a voltage of 0.33 p.u at the tie-line.

The use of the UPFC instead of other FACTS control-lers (used for less cost) is preferred due to the fact that the


Table 2 Results with and without the UPFC with programs GR: −500 MW, FYROM: −200 MW and ALBANIA: −200 MW

Cases LinesAC-1 AC-2 BC CD TTC (GR+AL+FYR)

Case 1, GR:−500, AL:−200, FYR: −200 MWLoading of the line (in % in MVA) 32.0% 8.0% 80% 43% 740Trans (MW) 31 −31 719 219

Case 2 with a 100 MVA UPFC in GR–AL tie lineLoading of the line (in % in MVA) 20% 17 % 68% 8% 910Trans (MW) 18 −137 619 0

UPFC offers the option of controlling the voltage and so thereactive power at the sending bus station. Moreover, due tothe fact of available 400-kV lines in the region and to weakresponse in damping of oscillations the UPFC is the preferredoption.

The previous results shown almost 20% (from 740 to 910)at the TTC increase that can be achieved by implementingfast reacting power flow controllers at the GR–AL tie line.

6 Conclusions

In this paper, a complete congestion management proce-dure was implemented starting from the preventive conges-tion management techniques that are currently used and theones that will be used in the future, followed by innova-tive correcting congestion management solutions that can beused at the day ahead stage, such as the implementation ofFACTS controllers. The analysis has shown that the explicitCA technique based on BCs is currently the most valuable intoday’s electricity markets. Moreover for the day ahead stage,the UPFC provides effective congestion elimination and in-creases considerably the TTC limit while keeping at the sametime the security constraints.

The decentralised market coupling method is from atheoretical point of view the ultimate preventive congestionmanagement technique, however its implementation is notexpected in the next few years due to legislation and coordi-nation problems among countries.

References

1. Brosda J, Handschin E, Leder C (2002) Hierarchical visualisationof network congestions. In: Proceedings of the 14th Power SystemComputation Conference, Spain, 2002

2. Brosda J, Handschin E (2001) Sequential quadratic program-ming and congestion management. Electrical engineering, vol 83.Springer, Berlin Heidelberg, pp 243–250

3. ETSO. Evaluation of congestion managementmethods, www.etso_net.org

4. CONSENTEC. Analysis of cross-border congestion managementmethods for the EU electricity market, www.consentec.de

5. ETSO. Reconciliation of market splitting with coordinated auctionconcepts-technical issues, www.etso.org

6. EUROPEX (2003) Using implicit auctions to manage cross-bordercongestion: decentralised market coupling. In: 10th meeting of theEuropean Electricity Regulation Forum, July 2003

7. Athanasiadis N (1999) Modelling, control and design of FACTS,custom Power devices and variable speed drives for transmissionand distribution system architectures. PhD thesis, University ofStrathclyde, UK

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